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Throughout the last decade, U.S. oil production has doubled from five million barrels of per day (MMbb/d) in 2017 to 10.4 MMbbl/d for the first half of 2018, with the bulk of the production increase being supplied from the Permian Basin.
During the same period, the complexion of the industry has changed considerably due to the shale revolution. For starters, there are fewer “mom and pop” companies and well-capitalized public and private equity-backed organizations have largely delivered this production growth.
The plight of today’s shale companies is characterized by high capital costs, hyperbolic production decline rates and the ability to exceed past performance through continuous advancements in technology.
The high delivery, yet rapidly declining production profile of shale reservoirs creates a bit of a treadmill for companies seeking production growth. Until as recently as last summer, accommodative debt and equity markets and private equity have largely financed this growth for companies that had capex budgets well in excess of their cash flow.
However, over the last 12 to 18 months, institutional investors have started to seek demonstrable returns and proof that the capital expenditures make economic sense and investors have begun to withhold equity capital from the industry. This begs the question: What should a shale exploitation company look like?
Many have described shale development as a manufacturing process. However, because of the idiosyncrasies of any given location and within any given reservoir, I prefer to think of it as a repetitive construction project, with each project (well) requiring a bespoke set of adjustments and alterations to maximize its value.
In order to construct an economical well, a critical path of multiple events must be synchronized and flawlessly executed, including title assurance and DOI development, permitting, and on-time material and equipment delivery. This also entails the orchestration of all the service company professionals who touch the drilling, cementing, completion, flowback, facilities installation and other activities required to turn a given well to production.
More than 60% of the wells drilled today are from pads. This enables more efficient drilling and completion, as rig and equipment mobilization and demobilization costs are minimized. It also provides for more efficient production operations through the utilization of centralized/common production facilities.
However, this type of development plan also requires a tremendous amount of capital (eight wells at $12 million/copy), as the pad is fully developed awaiting first production.
This type of project staging leads to a lumpy cash flow profile from any individual pad; however, if multiple pads are in various stages of simultaneous development, cash flows can be smoothed. In this environment, the company with the lowest cost of capital will win, but it must also have a balance sheet that can handle this level of work-in-progress
Scale matters, and the larger companies with hundreds of thousands of acres can be more efficient than companies with a few thousand. We are currently seeing competitors in every basin doing acreage swaps in order to square up their acreage so as to drill longer, more efficient, laterals across multiple, 1,280-acre spacing units.
Large operators can also lock in returns by forward hedging commodity price risk, securing firm transportation for pipeline access to minimize basis risk, entering long-term drilling contracts, obtaining dedicated frac crews, and pre-purchasing pipe, sand and other supplies.
With ongoing pad development, producers can also use modular production facilities that can be swapped out, right-sized and moved from pad to pad as volumes and pressures drop following the initial production from any group of wells.
These facility designs prevent the overengineering—and the attendant stranded capital—for production facilities that will be oversized after 18 months of production. In areas such as the Eagle Ford, where there is a geographically known gradient in oil gravity and volatility, production can be blended to satisfy pipeline constraints and maximize pricing.
The certainty of market access, commodity pricing, capital efficiency and cost containment outlined above, provides well-capitalized companies the ability to provide a clear line of sight on the investor returns which the public markets are demanding. There is value at scale and a certain level of operation needs to be achieved before dividends can be reliably sustained.
As the U.S. shale revolution enters its second decade, its development has provided a legitimate boost to the U.S. quest for energy independence and has positioned the United States as the world’s marginal oil producer.
As the industry continues to evolve, look for considerable consolidation (Concho/RSP Permian) in the key shale basins as the industry struggles to find the optimal organizational size for efficient and flexible exploitation of its resource base while concurrently satisfying the needs of its shareholders.
Brock Hudson is a managing director at Carl Marks Advisors. He has over 30 years of oil and gas asset management and financial transaction experience including seventeen years in oil and gas asset investment management and twelve years as a reserve-based energy lender. Hudson specializes in structuring and leading complex and innovative acquisitions, divestitures and financial transactions and capital raising. He can be reached at email@example.com.
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